Experimental Study of CO2 Injection Into Saline Formations

Abstract

Abstract We present experiments at the laboratory scale to investigate the influence of gravitational, viscous and capillary effects on the CO2 injection process. Two-dimensional experiments are performed in a vertical glass-bead pack, in the parameter range of practical flows, i.e., with Bond numbers of about 10[-3], and capillary numbers of the order 10[-4]. Experiments are carried out primarily to demonstrate the type of flow regimes that occur under favorable as well as uncomfortable conditions of density and viscosity. Experiments demonstrate the existence of pore scale instability in the presence of unfavorable gradients of viscosity and density, and as such, appear to be incapable of being modeled by conventional means. A comparison with estimates from percolation theory shows good agreement with experimental observations. Introduction Deep saline formations provide a large capacity for the sequestration of CO2 that is readily accessible in most sedimentary basins worldwide.[1] Sequestration takes place mainly through a combination of capillary, hydrodynamics and chemical trapping mechanisms. The process can be broadly classified into three phases: The injection phase where super-critical CO2 is injected into the site, the post-injection period of rising gas plume, and the final stage where gravitationally unstable convective mixing as well as chemical reactions between CO2 and rock minerals are expected to take place.[2] All trapping mechanisms are either unavailable or of negligible importance during the injection period because no residual trapping occurs during the drainage process, hydrodynamic trapping requires a longer time for dissolution and eventual convective mixing and chemical trapping is thought to occur over still larger time scales. The potential for CO2 storage in saline aquifers is largely determined by the storage capacity and the CO2 injectivity of the site. The storage capacity of aquifers depends on aquifer volume, porosity, and most importantly, on volumetric as well as microscopic displacement efficiencies. Injectivity on the other hand is governed by permeability, relative permeability, fracture characteristics of the rock, and rock compressibility.[3] The ability to make practical predictions regarding the storage capacity is based on the accuracy with which the microscopic multiphase flow process can be represented at the macroscopic field scale. Conventional modeling of CO2 injection, which is based on the Darcy formulation of two phase drainage displacement, requires the empirical estimation of multiphase flow quantities such as the relative permeability and the capillary pressure functions to completely characterize the flow. However, in order for those quantities to be meaningful, assumptions regarding compactness and stability of the flow at the microscopic scale as well as those of stability and uniformity of the flow at the macroscopic scale must be satisfied.[4,5] Experimental evident regarding both in the parameter range of interest for CO2 sequestration is lacking at present. Rather, fundamental analysis of drainage, although in a slightly different parameter range, precludes the applicability of the Darcy model because of non-compact or fractal behavior at the microscopic scale.[6,7,8] Even if one encounters stable microscopic behavior for some parameter combination, the macroscopic flow can potentially be unstable due to unfavorable gradients of density and viscosity (.e., brine displacement by supercritical CO2), and requires non-equilibrium treatment of the coefficients bridging the two scales.[9]